Post on 07-Jul-2018
transcript
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Centralizers: A Review
Date:
Apri l 17, 2014
To:
Lauren Boyd and Greg Stillman
United States Department o !nergy
"rom:
#iann Su
Sandia $ational La%oratories
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IntroductionWell completions are an integral part of providing safe, reliable and continuous
access to underground resources such as oil, gas and geothermal resources.
Completions are typically considered to be the nal step of drilling engineeringwhich includes processes such as setting casing, cementing, and perforating to
reach the target formation !". Completions provide the conduit from the resource
to the surface. Although completions encompass a wide range of disciplines,
several #ey factors ultimately determine the $uality of the completion. %ne of those
is cementing and centralizing casing within the wellbore.
Centralizers provide the restoring force to #eep casing centered in a wellbore. &his
centralization provides a uniform space between the casing and wellbore to
promote good cementing, and thus isolating 'uids from di(erent zones in a
formation.
&his white paper e)amines the current state of the art for centralizers in the conte)t
of well completions. &he paper will include an introductory primer on well
completions to provide the framewor# for the centralizer discussions. &he types of
centralizers currently available and how they are used will be discussed in addition
to alternative centralizer techni$ues.
Well Completions
What are well completions?
Well completion is the process of ma#ing a well ready for production or in*ection +".t is a multi-discipline systems engineering tas# involving geology, drilling,
cementing, and production. &he goal of the completion is to provide a safe and
ecient conduit from the formation to the surface. A good well completion must
minimize formation damage, maintain good communication between the reservoir
and wellbore, and ma)imize reservoir productivity !". A completion design re$uires
not only sound science and engineering, but also practical hands-on wellsite
e)perience. A balance of theoretical and practical tends to produce the best results
/".
Well design and completion typically depends on regulatory as well as economic
issues. Completions are often divided between reservoir completion and production
completion. &he reservoir completion is relates to the connection between the
reservoir and the well. &he production completion is the conduit from reservoir to
the surface.
0ey considerations for reservoir completion include the following /":
- Well tra*ectory and inclination
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- %pen hole vs. cased hole- 1and control re$uirement and type of sand control- 1timulation re$uirements- 1ingle or multi-zone- 2roducing or in*ecting well
n the production completion, #ey factors include
- 2roduction thru casing or tubing- Articial lift and type- Anticipated production rate- 3luid produced or in*ected- Anticipated corrosion resistance- &hermal cycling- 1ingle or multiple completion- 4)pected di(erential pressures
Types of reservoir completions &he type of completion chosen depends on reservoir characteristics and production
re$uirements. &here are two basic types of completions: open-hole and cased-hole.
Open-hole completion
An open-hole completion is the most basic type of well completion. t encompasses
several techni$ues with the commonality being casing does not cross the reservoir.
Although it is the simplest type of completion, it is typically reserved for competent
formations capable of withstanding production conditions. &his is more li#ely to
occur in geothermal drilling than oil 5 gas. %pen-hole completions can be
performed in both vertical and horizontal wells.
n open-hole completions, the well is drilled to the top of the formation. Casing is
then run to the formation without crossing the reservoir 63igure !7. 2roduced 'uids
are allowed to 'ow directly into the wellbore. Without a liner, this type of
completion is also #nown as a barefoot completion.
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Figure 1. arefoot open-hole completion illustration
&he barefoot techni$ue does have some limitations. 8onal isolation during
production or in*ection operations is more challenging and reservoir and fracturing
stimulation options are limited to the use of open-hole pac#ers 6sometimes not
feasible7 or possibly diverter based technologies. Additionally, controlling 'ow of
'uids from the formation can be dicult.
Another type of open-hole completion is a liner completion 63igure +7. t is used in
deep well completions where formation collapse is an issue. A liner is a string of
casing that does not reach the surface. t is hung from a previously installed casing
string using a liner hanger. 9tilizing pre-drilled or slotted liners in the formation,
this completion techni$ue provides additional formation control in the production
zone. &he liner can be used in con*unction with e)ternal casing pac#ers to provide
zonal isolation. &he liner also provides support to prevent formation collapse and
allows zonal isolation pac#ers to be deployed. enerally, pre-drilled liners are
preferred over pre-slotted liners because of the larger in'ow area and higher
strength /". &he use of slotted liners is common in geothermal completions.
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Figure !. "lotted liner completion
Cased-hole completion
Cased-hole completion di(ers from open-hole completions in that casing is run
through the production zone and cemented in place. &he casing is selectively
perforated using a perforator 6commonly an e)plosive shaped charge7 to connect
the formation to the casing 63igure /7. &he perforator penetrates the production
casing and the cement sheath and creates a channel to allow the reservoir toproduce into the well !".
&his type of completion provides advantages in zonal isolation. A fully cemented
production zone allows more homogeneous 'ow of 'uids along the wellbore ;". t
also permits selected shuto( of unwanted 'ow. t is also useful for selective
hydraulic fracturing and acidizing.
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Figure #. $erforated casing completion
&he most obvious drawbac# to perforated casing completion is the increased costs
associated with running casing to the production zone. &his can be signicant when
wor#ing in high angles or long intervals. A drawbac# when wor#ing with
hydrothermal systems is that cementing across production zones is dicult and
would cut o( the desired wor#ing 'uid. Additionally, the high 'ow rates re$uired in
those systems are susceptible to 'ow restrictions from the perforations.
A variation on the casing perforation is liner perforation. n this method, a liner is
hung from the intermediate casing and then cemented and perforated. 2erforated
liner completion ta#es advantage of the seal created by the intermediate casing.
&he overall weight of the casing string and volume of cement can be reduced, thus
decreasing completion cost. &his is a common completion techni$ue for medium or
low pressure deep oil and gas wells !".
n both techni$ues, perforations are performed using shaped charges 63igure ;7.
&he charge creates a high pressure focused *et that penetrates the casing. &he
shaped charges are arranged inside a perforation gun to create a desired pattern. &he pressure pulse deforms the casing and crushes the cement and formation.
2ressures generated by the pulse can reach !< million psi /". =ebris generated in
the vicinity of the charge must be removed afterwards.
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Figure %. "haped charge
Ta&le 1. Completion service condtions 'adapted from (1)*
Completion +ode "ervice Conditions for ,se
Open hole
'&arefoot*
- Competent roc# reservoir- %il 5 gas reservoir without gas cap, bottom water,
water-bearing interbed- 1ingle thic# reservoir or mutli-zone layer with
similar pressure and lithology- >o zonal isolation re$uired
Open hole 'liner* - %il and gas reservoir without gas cap, bottom water- 1ingle thic# reservoir or multi-zone reservoir with
same pressure and lithology
- 8onal isolation not re$uired- 9nconsolidated medium and coarse grain sand
reservoir
Cased-hole - 8onal isolation re$uired due to complicated
geological conditions- ?ow-permeability reservoir that re$uires hydraulic
fracturing- 1andstone reservoir and fractured reservoir
Casing
Casing provides the controlled 'ow path from the production zone to the surface
and is a #ey component in completions. t protects the wellbore from the
surrounding environment and the surrounding environment from produced 'uids
and prevents the formation from collapsing.
Well casing is comprised of a metal tubes installed in drilled holes. &here are ve
types of casing based on function.
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Conductor casing
&he conductor string acts as a guide for the remaining casing in the hole. t is the
rst string cemented to the top and tted with casing head and blowout prevention
e$uipment. t is shallow, typically between +@-
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&he depth of each section is determined based on having the borehole pressure
being greater than the pore pressure but less than the fracture pressure F" or to
case a section of the well that is #nown a priori to be problematic. 3rom there, the
casing and hole sizes are determined. Dit sizes are chosen to provide between +.@in
to ;.@in between the casing and the wellbore to allow for good cementing. >ewer
regulations re$uire +.@in of cement on all sides and are becoming standard in mostareas.
Casing designations
Casing is classied according to the way it is manufactured, the grade of steel used,
dimensions, and type of coupling. A2 1pec early all metal used in completions is some form of steel with occasional niche
application of titanium which is immune to corrosion and resistant to hydrogenembrittlement in geothermal brines /". ?ow alloy steels are the starting point for
material selection. Completion components typically use the American ron and
1teel nstitute 6A17 four-digit system for classifying low-alloy steels. &he 9nied
>umbering 1ystem 69>17 system is also commonly used.
Alloy steels 6metal concentration other than iron I
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of casing materials. 4lements such chromium help to improve corrosion resistance.
>ic#el improves toughness as well as corrosion resistance. &able / lists common
alloying elements and their e(ect on the bul# properties of the material.
Ta&le #. /lloying elements for steel (#)
/lloying 0lement $urposeChromium mprove corrosion resistance
>ic#el mprove toughness, useful in presence of K1
olybdenum ncrease high-temperature strength, resistance to
pitting
anganese ncreases hardenability
&itanium 1trengthen steel
A commonly used alloy recognized by A2 is ?G@ !/Cr. t is similar to ?G@ carbon
steel but with !/B chromium. ?G@ !/Cr is common in many o(shore wells and
geothermal. >ic#el alloys are used for high-strength high corrosion resistantapplications.
Coatings and liners can be used where the cost of corrosion resistant materials is
beyond reach. &he liner can be used with relatively ine)pensive steel to produce
the desired results.
Cementing
2rimary cementing 6cementing the casing and the liner7 is the most important
operation in the development of a well F". Cementing is usually performed as a
part of drilling with specialty contractor support. Cementing materials vary from
basic 2ortland to sophisticated specially formulated synthetic or late) cements. &hecement slurry is pumped to specic locations in the well. n geothermal, casing and
liners are normally cemented to the surface. When cured, the cement slurry
provides a bond between casing and the wellbore that controls the 'ow of 'uids in
and around the wellbore.
n addition to providing structural support to casing, primary cementing also isolates
porous formations from the production zone, prevents unwanted sub-surface 'uids
from entering the producing interval, protects casing from corrosion, and connes
abnormal formation pressures.
Cementing has a specic purpose for each of the strings described in the previoussection. 3or conductor casing, cement prevents drilling 'uid from circulating
outside the casing. 1urface casing is cemented to protect freshwater formations
near the surface and provide a structural connection between the casing and
formation. n intermediate casing string, cement seals o( abnormal pressure
formations. 2roduction casing is cemented to prevent the mi)ing of produced and
non-produced 'uids.
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Cements are divided into nine classes by the American 2etroleum nstitute 6A27.
&he classes describe the intended application for each of the cement types.
Ta&le %. /$I cement classes (1 2)
Clas
s
3epth ange $roperties
/ 1urface to E,@@@
ft
no special properties re$uired
1urface to E,@@@
ft
moderate to high sulfate resistance
C 1urface to E,@@@
ft
high early strength re$uired and high sulfate resistance
3 E,@@@ ft L !@,@@@
ft
moderately high temperatures and pressures. Available
in both moderate and high sulfate resistance
0 !@,@@@ ft L
!;,@@@ ft
high temperatures and pressures.
F !@,@@@ ft L
!E,@@@ ft
e)tremely high temperatures and pressures. Available
in both moderate and high-sulfate resistance
4 1urface to G,@@@
ft
can be used with accelerators and retarders for wide
range of depths and temperatures. Available moderate
and high-sulfate resistance. Dasic oil well cement
5 1urface to G,@@@
ft
can be used with accelerators and retarders for wide
range of depths and temperatures. Available moderate
and high-sulfate resistance. Dasic oil well cement 6 !+,@@@ ft L
!E,@@@ ft
4)tremely high temperatures and pressures. Can be
used with accelerators and retarders.
n oil and gas, one of the crucial characteristics of any well cement is sulfate
resistance. 1ulfate is abundant in underground formation li$uids that can contact
the set cement. &he chemical reaction between the sulfate and cement can corrode
the set cement causing e)pansion resulting in cement disintegration. &he relative
increase in sulfate resistance indicated in &able ; indicates decreasing amounts of
tricalcium aluminate. n geothermal, acid and C%+ resistance are of primary
importance. Calcium aluminate phosphate 6Ca27 and sodium silicate-activated slag
611A17 cement have been shown to have good performance against C%+ attac# E".
n high-temperature environments such as geothermal wells, the principal binder in2ortland cement begins to lose strength M". &his occurs at temperatures e)ceeding
+/@N3. &hese limitations are addressed by using silica-lime cement which is more
stable at high temperatures !@". &he silica added to the cement helps to stabilize
it at high temperatures. n a silica-lime hydrothermal cement, calcium hydro)ide
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and silica are the only reactants. &his type of hydrothermal cement re$uires less
retardant and ta#es advantage of well temperatures 6I!M@N37 to set.
&he slurry and set cement should meet basic re$uirements for ensuring safety and
$uality of the cement *ob. Additional properties to consider include density,
thic#ening time, set strength.
&he density or specic weight is one of the most important properties of cement
slurry F". Cement slurry density should be higher than the density of the drilling
'uid but not high enough to induce fracturing in the wellbore. &he specic weight is
dened by the amount of water used with the dry cement. &he range of specic
weights is limited by the minimum and ma)imum standards set by A2. Kowever,
typical density that provides good 'owability and set strength is around !E lbHgal
!".
&he thic#ening time of the cement slurry must be #nown before prior to being used.
t is dened as the time re$uired to reach !@@ Dearden
!
units of consistency. F@Dearden units is typically considered the ma)imum pumpable viscosity F". f the
thic#ening time is e)ceeded, there is the ris# of damaging e$uipment and not lling
the annulus. &hic#ening time can be controlled with additives that will retard the
chemical reaction and e)tend the thic#ening time.
&he compressive set strength of cement indicates how much load the cement can
withstand before rupturing. A compressive set strength of
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Figure 7. Casing shoe illustration (11)
Above the guide shoe, the 'oat collar acts as a 'ow-control valve to prevent heavier
cement slurry from entering the casing from the annulus. &he 'oat shoe and 'oat
collar are run on a single string to provide chec# valve redundancy. &he 'oat collar
is part of a 'oat *oint. &he *oint is usually left full of cement to insure an ade$uate
supply of cement to the bottom outside of the casing. t provides a margin of safety
against casing volume calculation errors when estimating cement volumes.
n geothermal, it is common practice to cement to surface, so additional cement
volume is added for the inter-casing annulus and one watches for cement to return
to surface. ost geothermal regulations have special provisions for casing not
cemented to surface, and these provisions can be very e)pensive to implement. A
top *ob may be re$uired as the cement level nearly always falls as the cement
cures. n a top *ob cement is placed from the surface via a tremie pipe to ll the
annulus to the surface or very near the surface.
Centralizers are used to position the casing uniformly within the wellbore. &hey
help to insure the casing is centralized in the wellbore to allow a more uniform
distribution of cement slurry around the casing. Recommended positioning of thecentralizers is described in A2 R2 !@=-+. 3urther discussion about centralizers is
provided in the ne)t section.
&he casing string is lowered into the hole until the shoe is a few feet o( the bottom
of the hole. As it is lowered into the wellbore, the drilling mud is displaced and
stored in the mud tan#s, while an annulus of drilling mud remains in the wellbore.
&he casing string remains hanging throughout the cementing operation. &his allows
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the string to reciprocate and rotate to assist in securing a proper bond from the
casing to the formation.
After the casing string is lowered into position, a cementing head is made up to the
upper end of the string. &he cementing head contains two wiper plugs that are
essential to the cementing process 63igure E7. &he top wiper is solid and designedto build pressure in the casing. t maintains separation between the displacement
'uid and the cement slurry. &he bottom plug separates the drilling mud from the
cement slurry and has a rupture dis# that allows spacer and cement slurry to 'ow
into the annulus after a set pressure has been reached 6+@@-;@@ psi7.
Figure 8. Cement plugs (11)
nitially, both plugs are held in place with retaining pins in the cementing head
63igure Fa7. &he bottom pin is released when the spacer+ and cement slurry are
ready to be pumped into the casing 63igure Fb7. When all of the cement has been
pumped, the top wiper is released and a displacing 'uid 6often drilling mud7 is
pumped behind it 63igure Fc7. When the bottom plug reaches the 'oat collar, the
increase in pressure eventually causes the rupture dis# to burst. After the rupture
dis# bursts, the spacer 'ows into the annulus between the casing and the wellbore
and displaces the remaining drilling mud 63igure Fd7. Additional pumping drives theslurry cement into the annulus until the top plug reaches the bottom plug 63igure
Fe7. At this point, pressure in the pumps begins to build until a desired set point.
&he casing is then pressure tested 6from the outside to the inside7 to chec# for
lea#s.
+ 1pacer 'uid separates the drilling mud from the cement slurry. &he spacer
removes drilling mud ahead of the cement
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Figure 2. "ingle-stage cementing steps (1!)
&he displacement 'uid is usually lighter than the cement slurry. &his creates a
pressure imbalance and results in the casing being under compression while the
cement sets. &his preload allows the cement-casing interface to always be loaded
to improve the bond between the surfaces.
Reverse circulation cementing
n conventional %5 cementing operations, cement is typically not run bac# to the
surface. %nly a portion of the casing is cemented in place. Kowever, in geothermal
where high thermal stresses re$uire uniform cement over the full length of casing,
cement is run all the way bac# to the surface.
9sing conventional cementing techni$ues, this creates uni$ue challenges. &he high
pump pressures re$uired to pump cement bac# to the surface create high downhole
pressures. &his can lead to lost circulation where the cement is pumped into the
formation rather than bac# up the annulus. &he high pump pressures can also
O'oatP the string !/".
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M7. A mar#er along with the tail slurry is initially pumped into the annulus. ?ead
slurry is then pumped in to displace the tail slurry into the shoe. &he slurry
continues 'owing through the drill pipe until the mar#er is seen at the surface.
Figure ;. "ta&-through with marer to surface
1tab-&hrough ?ead to 1urface
n this variety of stab-through reverse circulation, lead cement is pumped down the
annulus and displaced up the drill pipe 63igure !@7. When the lead cement is seen
at the surface, tail cement is pumped down the drill pipe, displacing the lead
cement at the shoe. ud or water is then pumped until only lead cement remainsin the annulus and the shoe.
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Figure 1o need to run stab-in
drill pipe in casing- Kighest pressure in
annulus after pumping
- &racer reliability- 1everal hundred feet
of cement to drill out- Casing shut in with
di(erential
hydrostatic pressure
at surface
"ta&-through
marer to surface
- Cement displacement
conrmed with returns tosurface
- inimize micro annulus
by controlling hydrostatic
di(erential downhole
- ncreased friction
from circulatingthrough drill pipe,
more pressure in
annulus
"ta&-through
lead to surface
- Conrmation of complete
ll with returns to surface- 2recise tail slurry
- Kigher 4C= than
other reverse
circulation
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positioning around shoe- ?ess cement to drill out
of casing- =ecrease in hydrostatic
pressure on annulus
techni$ues- Additional rig-up time
to pump tail cement
"ta&-throughfoamed cement
- ?ower hydrostaticpressure- 2ositive verication when
annulus is lled- 2recision placement of
tail slurry around shoe
- Kigher 4C= thanother reverse
circulation
techni$ues due to
friction in drill pipe
when circulating to
surface- Additional rig-up time
to pump tail cement- 9se of nitrogen
increases comple)ity
of setup
Centrali>ersA centralizer is a piece of hardware tted onto casing or liner to #eep it centered in
the borehole during cementing operations. &he $uality of a cement *ob is largely
dependent upon the centralization between casing and the wellbore. A centralized
casing allows cement to 'ow uniformly in the annulus as well as enabling ade$uate
mud removal. &he #ey to that is removing mud in the annulus between the casing
and borehole and replacing it with cement. =ue to di(erences in properties
between the mud and cement, there is a tendency for cement to leave behind mud
channels ;". &he stando( provided by centralizers is one of the most important
factors in preventing the mud poc#ets 63igure !+7.
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Figure 1!. Illustration of eect of poor stando on cement
ntroducing additional motion while running casing is another techni$ue used to
improve mud removal. Reciprocation, rotation, and the combination of both are
often used to aid casing downhole. Centralizers can act as rotational bearings to
help pipe rotation.
n open-hole sections, centralizers play an important role in preventing di(erential
stic#ing. 3igure !/ illustrates how centralized casing can help to eliminate
di(erential stic#ing. 3or centralized casing, the pressure e)erted on the casing by
the drilling mud is uniformly applied. &his means there is no net force beyond
gravity acting on the casing. f the casing is allowed to settle into the mud ca#e, the
contact area between the mud ca#e and casing can approach !H; of the total
surface area of the pipe ;". &his di(erential area results in a net side force driving
the casing into the mud ca#e. f this side force e)ceeds the force available to run
the casing, then the pipe becomes stuc#. Although there is additional running force
when centralizers are used, their use can prevent stuc# pipe scenarios.
Figure 1#. 3ierential sticing illustration
Although centralizers are typically anonymous hardware, they made headlines in
the =eepwater Korizon incident. &he number of centralizers used in the well was
the sub*ect of scrutiny during the investigation. &he original well plan called for +!
centralizers to be used for the completion. Kowever, various underlying conditions
resulted in only using si) centralizers and a nitrogen foam cement program.
According to an incident report Othe resulting cement program was of minimal
$uantity, left little margin for error, and was not tested ade$uately before or after
the cementing operation. 3urther, the integrity of the cement may have been
compromised by contamination, instability, and an inade$uate number of devices
used to center the casing in the wellbore.P !E"
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A case study published in !F" shows the e(ect of casing centralizers on a cement
*ob. A total of !EE centralizers were used in a !;,/!< ft. well. &he centralizers
allowed the operator to save time and cost by eliminating the e)pense of washing
and reaming or casing 'otation. n the study, two sub*ect wells were used for
comparison. Results from cement bond logs show that the rst well was centralized
on every *oint in the curve and lateral and the *oints from the #ic# o( point to thetop of the cement. &he second well was not centralized and showed several areas
of poor cement bond. &he centralized well showed an overall higher $uality cement
sheath. 3indings from the study resulted in operational changes to include more
centralizers and decrease the spacing.
Types of centrali>ersCentralizers are divided into two basic categories: bow-type and rigid 63igure !;7.
&he utility of each depends on the particular application. Dow springs have been
designed for traditional applications such as vertical or slightly deviated wells while
rigid centralizers are suited for horizontal and e)tended reach applications. &he
main purpose of each is to provide uniform spacing between casing or pipe and the
wellbore.
a. Dow-spring centralizer b. Rigid centralizerFigure 1%. asic centrali>ers (19)
Dow-spring centralizers are made from a set of 'e)ible springs attached to two
collars. &he 'e)ible bows generate a restoring force that creates separation
between the casing and wellbore. &he shape, size, and number of bows can varydepending on the particular application. 2erformance re$uirements such as starting
force, restoring force, and testing for bow-spring centralizers are dened in A2 1pec
!@= !M". 1ince the outer diameter of the bows is typically larger than the well
diameter, bow springs are suitable for use in washout areas.
Within the bow-spring category, there are both non-welded and welded centralizers.
&he non-welded type performs well under compressive loads and is used in
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standard applications where no rotation is re$uired or minimizing drag force is not a
consideration. &hese centralizers are not optimized for holeHpipe size combinations
so they tend to be less e)pensive than other types.
Welded bow-spring centralizers are optimized for specic pipe and hole size
combinations which result in lower drag forces. &he welded design provides betterperformance under tensile loads and allows rotation of the stringHcasing within the
centralizer. &he lower running force and higher restoring force ma#e this type of
centralizer a good choice when operating in washed out and highly inclined sections
+@".
&he di(erence in performance between welded and non-welded centralizers is due
to the way the bows are attached to the collars. n non-welded centralizers, the
bows are attached to the collars in a way that allows them to hinge. 3or welded
centralizers, the bows are welded to the collars providing more rigidity in the
centralizer.
Rigid centralizers are used when drag forces have to be minimized such as in long
horizontal or highly deviated wells. Rigid centralizers can be used in slimhole
environments, close tolerance drift diameters, and to help reduce friction in
e)tended reach laterals +!". Kelical blade designs help to enhance circulation and
hole cleaning. &ungsten carbide hardfacing or other friction reduction techni$ues
are also available ++". &hey are also used when the lateral forces e)ceed the
spring compressibility. ?i#e the bow-spring centralizers, there are two main sub-
categories for rigid centralizers. &hey are solid body and nned type.
1olid body rigid centralizers are made from a cast material, usually a metal alloy or
non-metallic composite 63igure !
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Figure 17. "olid &ody centrali>er with spiral @ns (!%)
Kollow n rigid centralizers 63igure !;b7 are the other type of rigid centralizer. &hey
consist of straight or spiral hollow steel ns welded to steel collars. &he shape of
the ns is designed to minimize drag forces while running pipe. &he ns also have a
pre-dened collapse load to yield under stuc#-pipe conditions. &he reduced drag
design also enables reciprocation as well as rotation while running pipe. &hey have
a larger 'ow-by area compared to solid body centralizers thus reducing circulating
pressures. Decause of these characteristics, they are well suited for use in highly
deviated or horizontal wells. &hey are used in con*unction with stop collars to
properly locate the centralizers on the casing.
&he balance between running force and restoring force is a #ey factor in selecting
the right centralizer. Commercial software is available to assist in modeling forces,displacements, a positioning. Kowever, if those tools are not available, &able E
provides some basic guidance for choosing centralizers.
Ta&le 8. "election criteria for centrali>er type '&ow or rigid* (%)
ow Type igid
>on-weld Welded 1olid Dody 3innedotating
liner
applications
>ot advisable 4)cellent ood 4)cellent
+inimi>e
drag force
>ot optimized 4)cellent ood 4)cellent
5igh &uild
rate
ood ood >ot advisable ood
$assing
restrictions
in well&ore
ood ood >o 2ass without
damage
5ydrodynami
cs
>ot optimized ood ood %ptimized
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$assing
casing
windows
9se caution ood 9se caution ood
4auge hole 4)cellent 4)cellent 4)cellent 4)cellent"lightly
oversi>e hole
4)cellent 4)cellent ood ood
Aarge
washout
section
4)cellent ood >ot advisable >ot advisable
,nder gauge
hole
ood ood >o >o
5ow do I use them?2ositioning centralizers in the correct place down hole is critical to their utility.
&echni$ues for establishing centralizer placement have been published in the
literature +
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1s 1tando( at the sag point
Figure 18. Calculation of casing stando in a well&ore
3or perfectly centered casing, the annular clearance la is given by
2
w p
a
D Dl
−=
!!Q 4R43%RA& 67
where D& is the wellbore diameter and D p is the casing outside diameter. &he
stando( at the centralizer is indicated by S' in 3igure !E. 3or a bow-spring
centralizer, the stando( is given by the load-de'ection curve of the centralizer
tested in a particular hole size and an applied lateral load. &his information is
typically provided in the centralizer specications. 3or a rigid centralizer, the
stando( is determined by
2
c p
c
D DS
−=
++Q 4R43%RA& 67
where D' is the outside diameter of the centralizer. &he stando( at the sag point 1s
is then given by
s cS S δ = − //Q 4R43%RA& 67
whereSs
is the stando( at the sag point andδ is the ma)imum de'ection of thecasing between the centralizers.
n practice, the minimum stando( may be located between the centralizers where δ
is the ma)imum or at the centralizers. &he stando( S of a section of casing is the
minimum of the stando( at the centralizers or the stando( at the sag point.
&he stando( ratio is then dened by 4$uation ;.
100 sa
S R
l = ×
;;Q 4R43%RA& 67
Changes in inclination angle or other factors such as tension in the casing have an
impact on stando( re$uirements and centralizer placement. &he de'ection of the
casing in the wellbore depends on these loading conditions. Dased on beam theory,
de'ections for common loading scenarios have been derived and captured in the
literature +
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Aoading Condition +aBimum Casing 3e:ection
13 straight inclined
well&ore without aBial
tension
( ) 4sin
384
b cW l
E I
θ δ =
×
13 straight inclinedwell&ore with aBial
tension
( )4 24
cosh 1sin 24
384 2 sinh
b cW l
E I
µ µ θ µ δ
µ µ × − = − ÷ ÷ ÷×
2
4
t c F l
E I µ
×=
×
!3 well&ore ( )3 2
4
cosh 124
384 2 sinh
l c F l
E I
µ µ µ δ
µ µ
× − × = − ÷ ÷ ×
sin 2 sin2
l b c t F W l F β θ = × × + ×
6decreasing inclination7
sin 2 sin2
l b c t F W l F β
θ = × × − ×
6increasing inclination7
#3 well&ore ( )3 2
4
cosh 124
384 2 sinh
l c F l
E I
µ µ µ δ
µ µ
× − × = − ÷ ÷ ×
2 2, ,l l dp l p F F F = +
, cos 2 sin2
l dp b c n t F W l F β
γ = × × + ×
6decreasing inclination7
, cos 2 sin2
l dp b c n t F W l F β
γ = × × − ×
6increasing inclination7
( )
( )
1 2 1 2sin 2
cos sinsin 2 2
n
θ θ θ θ γ
β
− + = ÷
( )1 1 2 1 2 2 1cos [cos cos sin sin cosβ θ θ θ θ φ φ
−
= + −
, 0cos
l p b c F W l γ = × ×
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=enitions for symbols in the above e$uations are given in &able G.
Ta&le 9. 3e@nitions for terms used in de:ection calculations
"ym&o
l
3e@nition
a)imum de'ection of casing betweencentralizers
W& Duoyed weight of casing per unit length
θ
Wellbore inclination angle
lc =istance between centralizers
0 odulus of elasticity of casing
I Area moment of inertia of casingFt 4(ective tension below centralizer
θ
Average wellbore inclination between two
centralizers
r Radius of curvature of wellbore path
&otal angle change between centralizers
γn Angle between gravity vector and principal
normal of wellbore
γ< Angle between gravity vector and binormal of
wellbore
φ
Azimuth angle
Fldp &otal lateral load in the dogleg plane
Flp &otal lateral load perpendicular to dogleg plane
&he recommended spacing between centralizers is determined by solving for l' in
the above e$uations.
2ositioning centralizers on the casing or pipe is done with stop collars or upset
features integrated into the bo) end of casing. 1top collars are typically held in
place using set screws or loc#ing pins 63igure !F7. 1ome are held in place with
resins or other adhesives while others use screws, nails, or mechanical dogs +F".
&hey can be independent of the centralizers or integrated into the centralizers.
According to A2 R2 !@=-+, the stop collar or holding device Oshall be capable of
preventing slippage.P &o accomplish this, the holding force of the stop collar shall
be greater than the starting force of the centralizer with additional margin built in
for varying well conditions.
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Kinged collar with cross-bolt 1et screw stop collar Figure 12. "top collar illustrations (!9)
n addition to centralizer spacing, installation patterns should also be considered.
Weatherford +;" provides guidelines for patterns suitable for various conditions
3igure !G. 3or optimal centering in Case , centralizers should be installed over stopcollars. &his type of installation can be performed prior to running the casing and
minimizes lost time. t is not recommended for close tolerance situations. Case is
well suited for centering in close-tolerance patterns. &his pattern can also be
installed prior to running the casing. n Case , the centralizer is installed between
a stop collar and casing coupling. &his allows the centralizer limited travel and
re$uires only one stop collar per centralizer. Case S places centralizers over casing
couplings and reduces annular 'ow area. &his arrangement is typically avoided.
Case :
%ver stop collars
Case :
Detween stop
Case :
Detween couplings
Case S:
%ver couplings
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collars and stop collarsFigure 19. ecommended installation patterns (!%)
Why wouldnt I use centrali>ers? &he importance of using centralizers in achieving good cementing results is well
#nown, however, they are often used with less than optimum placement due to
fears of the inability to the casing point. ;". Dow spring centralizers have wor#ed
well in traditional low angle and vertical wells, but e)tended reach and horizontal
wells re$uire more specialized centralizers.
&he 'e)ible bows create a restoring force that creates separation between the
casing and wellbore. &he restoring force, however creates a friction force between
the casing and the wall. &his running force adds considerable drag and can prevent
running casing to the desired casing point.
Korizontal and e)tended reach wells present increased challenges to getting casing
to bottom compared to vertical wells. Casing in high angle sections will have to be
pushed into the hole rather than allowing them to slide down with gravity. &he need
to push the casing through the hole can lead to buc#ling of the casing as it is run.
3or casing to slide down the hole, the a)ial force must be greater than the drag
force. f the a)ial compressive forces are large enough, sinusoidal buc#ling in the
casing can occur. Deyond sinusoidal buc#ling, helical buc#ling can also become a
concern. n helical buc#ling, additional side forces can be signicant !F".
Additionally, there are #nown cases of centralizers being damaged or destroyed
while running casing. A eld study by +M" showed that centralizers are susceptible
to damage while being run, especially as they e)it casing. &hey discovered several
failures of centralizers run on liners in the transition from intermediate casing to thehorizontal lateral. 1everal types of rigid centralizers were tested in the lab to
determine the failure mechanisms. &hey concluded that a variety of factors can
a(ect centralizer performance including the blade shape and the diameter relative
to the opening.
/lternative centrali>ersA case study of a downhole-activated centralizer 6=AC7 was presented by /@". &he
centralizer was designed for use in highly inclined wells and other restrictions such
as close tolerance wellheads. t was designed to be activated with e)ternal
hydraulic pressure, temperature, or by chemical reaction. &he activated
centralizers were tested in two o(shore wells near taly.
&he =AC was designed to allow optimum stando( in applications where
conventional centralizers reach their limits. &he centralizer has a low running force
and is activated downhole once the casing is in place. &he =AC is based upon a
conventional non-weld bow centralizer. &he bows are held down in the running
position with a steel band. A loc# is used to hold the band in place until the
mechanism is activated.
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&he downhole activated centralizers were tested in two development wells.
Centralizer spacing was computed based on A2 !@=-+. 3ield tests showed the
e(ectiveness of downhole activated centralizers. &he measured hoo# load was in
line with predicted hoo# load indicating the centralizers deployed as predicted. &he
drag forces were reduced, but the restoring force was still limited by the bow-spring
design.
Figure 1;. 3ownhole activated centrali>er (#
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Figure !er with @ns (#1)
3esigning a etter WheelCentralizers fall into two basic categories: 'e)ible and rigid. 3rom a positioning
capability perspective, they are either )ed force or )ed displacement devices.
&hese passive devices have inherent deployment limitations. %ftentimes
centralizers are omitted for fear of causing issues reaching the casing point. A 'at
pac# centralizer that could produce a variable displacement when needed would
help to eliminate some of the issues associated with current centralizing techni$ues.
An alternative to the current selection of centralizers would be capable of producing
controlled forces and displacements comparable to the bow spring with little or no
installation drag. &he new centralizer would leverage e)isting techni$ues and
technologies for deployment mechanisms in a limited space and generate large
forcesHdisplacements. &he active centralizer will be able to operate in situations
where the bow spring and rigid centralizer would not be deployed.
3or bow spring centralizers, the drag force is directly proportional to the centralizing
force. f the centralizer can be deployed in a retracted position, the installation drag
is minimized which eliminates the limits on centralizer performance. Without that
limitation, the centralizer can be used more eciently, whether by applying higher
forces or controlled displacements when needed.
&his can be achieved through an active centralizer system as shown in 3igure +!.
&he active centralizer will allow a large centralizing force compared to a traditional
bow spring with little or no installation drag. Additionally larger displacements can
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be produced with a powered system to centralize the casing in e)tremely deviated
well bores. =epending on the re$uirements, the powered centralizer could be
deployed with a range of technologies that include paran actuators, shape
memory alloys, energetic materials 6gas generators7, etc.
Figure !1. 3eploya&le centrali>er concept
&he centralizer would be run in with the casing in the retracted conguration. &he
retracted conguration would still provide a minimal stando( between the casing
and the wellbore to prevent di(erential stic#ing. When it reaches the desired
location, it would deploy based on one of the methods previously described. &he
on-demand deployment helps to overcome the shortcomings associated with using
conventional centralizers.
1olving this problem will re$uire a systems-based approach. ntegrating the
centralizer with the casing, the environment, and the geology of the formation are
#ey factors to consider when developing this type of tool. Dy carefully dening the
problem re$uirements, a mechanism and power source can be developed for
geothermal applications. Accomplishing this will improve centralization of the
casing and help to eliminate failures associated with poor cement placement, thus
lowering the overall cost of well completion.
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/ppendiB
Centrali>er Terms and 3e@nitions
&he following terms and denitions are included to facilitate the discussion ofcentralizers and completions. &erms related to centralizers have been adapted
from A2 1pec !@=.
:eBedcondition of a bow-spring centralizer when force three times the specied minimum
restoring force has been applied to it
holding devicedevice employed to ) the stop collar or centralizer to the casing
holding force
ma)imum force re$uired to initiate slippage of a stop collar on the casing
hole si>ediameter of the wellbore
restoring forceforce e)erted by a centralizer against the casing to #eep it away from the wellbore
wall
rigid centrali>ercentralizer with bows that do not 'e)
running forcema)imum force re$uired to move a centralizer through a specied wellbore
diameter
solid centrali>ercentralizer made to be a solid device with non-'e)ible ns or bands
stando smallest distance between the outside diameter of the casing and the wellbore
stando ratioratio of stando( to annular clearance for perfectly centered casing
starting forcema)imum force re$uired to insert a centralizer into a specied wellbore diameter
stop collardevice attached to the casing to prevent moving of a casing centralizer
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eferences
!. Wan, R., Ad(an'ed &ell 'ompletion engineering. /rd ed. +@!!, Waltham, A:ulf 2rofessional 2ub. )), F!< p.
+. Wi#ipedia. )ompletion *oil and gas &ells+. +@!; cited +@!; 3ebruary,
http:HHwww.glossary.oileld.slb.comHenH&ermsHcHcementingUplug.asp) .!+. 1upport, 2. Single State )ementing 3peration. cited +@!; 3ebruary /"TAvailable from: http:HHpetroleumsupport.comHsingle-stage-cementing-operationH.
!/. Kernandez, R. and K. >guyen, e(erse8)ir'ulation )ementing and "oamedLate )ement !na%le Drilling in Lost8)ir'ulation ones, in ro'eedings orldGeot-ermal )ongress 2010. +@!@: Dali, ndonesia.
!;. Ric#ard, D., et al., e(erse )ir'ulation )ementing o Geot-ermal ells: A)omparison o ;et-ods6 RC &ransactions, +@!!. #7: p. ++
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!M. A2 1pec !@= 1pecication for Dow-1pring Casing Centralizers, A2, +@!@+@. 0inzel, K. and V.. artens, T-e Appli'ation o $e& )entrali.er Types to
/mpro(e one /solation in ori.ontal ells. !MMG.+!. Kalliburton, rote'- )B )entrali.ers. +@!@, Kalliburton Cementing.++. &41C%, ydro8"orm )entrali.ers, &41C% Corporation.+/. ammage, V.K., Ad(an'es in )asing )entrali.ation Using Spray ;etal
Te'-nology , in 3>s-ore Te'-nology )oneren'e. +@!!, %&C: Kouston, &.+;. Weatherford, ;e'-ani'al )ementing rodu'ts. +@@M, Weatherford
nternational ?td.+